<PAGE> 1
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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended: June 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from ________ to ________
Commission file number: 1-10216
CHIEFTAIN INTERNATIONAL, INC.
-----------------------------
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
Alberta, Canada None
------------------------------------------------------------- ------------------------------------
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
1201 TD Tower, 10088 - 102 Avenue,
Edmonton, Alberta, Canada T5J 2Z1
--------------------------------------- ----------------------
(Address of principal executive offices) (Zip Code/Postal Code)
</TABLE>
Registrant's telephone number, including area code: (780) 425-1950
Not Applicable
--------------------------------------------------------------------------
(Former name, former address and former fiscal year, if changed since last
report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) have been subject to such filing
requirements for the past 90 days.
Yes X No
------ -------
Indicate the number of shares outstanding of each of the issuer's class of
common stock, as of the latest practicable date.
Title of each class Date Number Outstanding
------------------- ------------- ------------------
Common shares July 17, 2000 16,224,059
<PAGE> 2
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CHIEFTAIN INTERNATIONAL, INC.
JUNE 30, 2000 FORM 10-Q QUARTERLY REPORT
TABLE OF CONTENTS
PART I
<TABLE>
<CAPTION>
PAGE NO.
<S> <C>
Item 1. Financial Statements
Consolidated Condensed Balance Sheet - June 30, 2000
and December 31, 1999 3
Consolidated Condensed Statement of Income (Loss) -
Six months ended June 30, 2000 and 1999 and Three
months ended June 30, 2000 and 1999 4
Consolidated Condensed Statement of Cash Flows - Six
months ended June 30, 2000 and 1999 5
Notes to Consolidated Condensed Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 9
PART II
Item 1. Legal Proceedings 18
Item 2. Changes in Securities 18
Item 3. Defaults Upon Senior Securities 18
Item 4. Submission of Matters to a Vote of Security Holders 18
Item 5. Other Information 18
Item 6. Exhibits and Reports on Form 8-K 18
Signatures 19
</TABLE>
<PAGE> 3
Page 3 of 19
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEET
(Full Cost Method of Accounting)
<TABLE>
<CAPTION>
JUNE 30, December 31,
2000 1999
---------------------------------------------------------------------------------------
(unaudited) (US $ in thousands)
<S> <C> <C>
ASSETS
Current assets:
Cash and short-term deposits $ 4,826 $ 19,368
Accounts receivable 26,496 18,855
Other 1,138 750
-------- --------
32,460 38,973
Capital assets - net 301,865 277,149
Deferred income taxes 13,743 14,636
-------- --------
$348,068 $330,758
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued $ 26,205 $ 25,369
Long-term debt 15,000 10,000
Abandonment cost accrual 9,095 8,595
Deferred income taxes 20,650 15,693
Shareholders' equity:
Preferred shares of a subsidiary 63,403 63,403
Common shares (Note 2) 237,076 237,076
Contributed surplus 26 26
Deficit (23,387) (29,404)
-------- --------
277,118 271,101
-------- --------
$348,068 $330,758
======== ========
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE> 4
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF INCOME (LOSS)
<TABLE>
<CAPTION>
Six months Three months
-------------------------- ----------------------------
Period ended June 30, 2000 1999 2000 1999
---------------------------------------------------------------------------------------------------------
(unaudited) (US $ in thousands except number of shares and per share amounts)
<S> <C> <C> <C> <C>
Production revenue, net of royalties $ 44,896 $ 30,385 $ 24,122 $ 17,351
Interest and other revenue 764 376 314 192
----------- ----------- ----------- -----------
Total net revenue 45,660 30,761 24,436 17,543
----------- ----------- ----------- -----------
Production costs 6,979 7,362 3,619 4,050
General and administrative expenses 3,194 2,373 1,401 1,044
Interest 406 1,201 228 636
Depletion and amortization 20,737 25,092 10,220 12,911
Additional depletion: Libyan
properties (Note 3) -- 11,393 -- 11,393
----------- ----------- ----------- -----------
Total expenses 31,316 47,421 15,468 30,034
----------- ----------- ----------- -----------
Income (loss) before income taxes and
dividends on preferred shares of a
subsidiary 14,344 (16,660) 8,968 (12,491)
Income taxes (Note 4) 5,856 (6,764) 3,820 (5,220)
----------- ----------- ----------- -----------
Income (loss) before dividends on
preferred shares of a subsidiary 8,488 (9,896) 5,148 (7,271)
Dividends on preferred shares of a
subsidiary 2,471 2,471 1,236 1,236
----------- ----------- ----------- -----------
Net income (loss) applicable to common
shares $ 6,017 $ (12,367) $ 3,912 (8,507)
=========== =========== =========== ===========
Net income (loss) per common share
(Note 5) -- Basic $ 0.37 $ (0.93) $ 0.24 (0.64)
=========== =========== =========== ===========
-- Fully diluted $ 0.36 $ (0.93) $ 0.23 $ (0.64)
=========== =========== =========== ===========
Weighted average number of common
shares outstanding:
-- Basic 16,224,059 13,351,267 16,224,059 13,348,391
=========== =========== =========== ===========
-- Fully diluted 17,363,535 13,351,267 17,385,819 13,348,391
=========== =========== =========== ===========
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE> 5
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CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 2000 1999
---------------------------------------------------------------------------------
(unaudited) (US $ in thousands)
<S> <C> <C>
Operating activities:
Net income (loss) applicable to common shares $ 6,017 $(12,367)
Items not requiring a current cash outlay 26,587 29,710
-------- --------
Cash flow from operations 32,604 17,343
Net change in non-cash operating working capital (Note 6) (7,811) (1,090)
-------- --------
Net cash inflows from operating activities 24,793 16,253
Financing activities:
Increase in long-term debt 5,000 5,000
Purchase of common shares for cancellation -- (80)
-------- --------
Net cash inflows from financing activities 5,000 4,920
Investing activities:
Lease acquisition, exploration and drilling costs (34,341) (16,182)
Pipelines and production equipment acquired (10,579) (3,675)
Sale of producing properties -- 155
-------- --------
Natural resource investing activities (44,920) (19,702)
Purchase of other capital assets (33) (24)
Change in investing accounts payable and accrued 618 (8,903)
-------- --------
Net cash outflows for investing activities (44,335) (28,629)
-------- --------
Change in cash and short-term deposits (14,542) (7,456)
Beginning cash and short-term deposits 19,368 10,613
-------- --------
Ending cash and short-term deposits $ 4,826 $ 3,157
======== ========
</TABLE>
See accompanying notes to consolidated condensed financial statements.
<PAGE> 6
Page 6 of 19
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 30, 2000 and 1999
(unaudited)
1. Basis of Presentation:
In the opinion of Chieftain International, Inc. (the "Company" and together
with its subsidiaries "Chieftain"), the accompanying unaudited consolidated
condensed financial statements contain all adjustments (consisting of only
normal recurring accruals) necessary to present fairly the financial
position as at June 30, 2000 and December 31, 1999 and the results of
operations and cash flows for the six month periods ended June 30, 2000 and
1999. Certain information and notes normally included in Chieftain's
financial statements prepared in conformity with Canadian generally
accepted accounting principles have been condensed or omitted for interim
reporting pursuant to the rules and regulations of the Securities and
Exchange Commission. These consolidated condensed financial statements
should be read in conjunction with the consolidated financial statements
and the notes thereto included in Chieftain's Annual Report on Form 10-K
for the year ended December 31, 1999.
Preparation of financial statements in conformity with generally accepted
accounting principles requires management to make informed judgements and
estimates. Actual results may differ from those estimates.
The results of operations and cash flows for the six month period ended
June 30, 2000 are not necessarily indicative of the results to be expected
for the full year.
Material differences between Canadian and US accounting principles that
affect Chieftain are referred to in Note 7, which provides the effects of
such differences on earnings and balance sheet accounts.
2. Common Shares:
(a) Common shares outstanding
At June 30, 2000, 16,224,059 (December 31, 1999 - 16,224,059) common
shares of the Company were issued and outstanding.
(b) Common shares reserved
At June 30, 2000, 1,500,000 (December 31, 1999 - 1,130,207) of the
authorized but unissued common shares of the Company were reserved for
issuance under the Share Option Plan. At June 30, 2000, the Company
had reserved 3,408,375 (December 31, 1999 - 3,408,375) common shares
for issuance pursuant to the conversion provisions of the preferred
shares of a subsidiary. See Note 2(c).
(c) Preferred shares of a subsidiary
Chieftain International Funding Corp. ("Funding"), a subsidiary of
Chieftain International (U.S.) Inc., sold 2,726,700 shares of $1.8125
cumulative convertible redeemable preferred shares at $25.00 per share
in a 1992 public offering in the US. The preferred shares are
redeemable, at the option of Funding, at $25.4028 per share during
2000, $25.2014 per share during 2001 and $25.00 per share after
December 31, 2001, plus accumulated and unpaid dividends. Each
preferred share has a liquidation preference of $25.00 and is
convertible at any time into 1.25 common shares of Chieftain
International, Inc. at the option of the holder.
3. Additional Depletion:
Additional depletion of $11.4 million arose from the termination of an
exploration program and production test in Libya.
<PAGE> 7
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4. Income Taxes:
The provision for income taxes differs from the amount of income tax
determined by applying the Canadian statutory rate to pre-tax income (loss)
before dividends paid on preferred shares of a subsidiary as a result of
the following:
<TABLE>
<CAPTION>
Six months Three months
------------------ ------------------
Period ended June 30, 2000 1999 2000 1999
----------------------------------------------------------------------------------------------
(US$ in thousands)
<S> <C> <C> <C> <C>
Tax at statutory Canadian rate of 44.62% $ 6,400 $(7,434) $4,002 $(5,574)
Lower income tax rate on earnings of US subsidiaries (1,273) 331 (810) 6
Reduction in value of deferred tax assets resulting
from reduction in future Canadian rate 329 -- 329 --
Other 400 339 299 348
------- ------- ------ -------
Tax at effective rate $ 5,856 $(6,764) $3,820 $(5,220)
======= ======= ====== =======
Effective tax rate 40.8% 40.6% 42.6% 41.8%
======= ======= ====== =======
</TABLE>
5. Per Share Amounts:
Net income (loss) per common share is computed by dividing net income
(loss) applicable to common shares by the weighted average number of common
shares outstanding during the period.
In the calculation of fully diluted earnings per share, shares outstanding
are adjusted for share options and shares issuable on conversion of
preferred shares where dilutive. Earnings are adjusted by the amount of
imputed interest on share option proceeds and preferred share dividends.
6. Supplemental Cash Flow Information:
Cash outflows for (inflows from) income taxes during the six months ended
June 30, 2000 were $69,000 (1999 -- $27,000). Cash outflows for long-term
debt interest during the six months ended June 30, 2000 were $324,000 (1999
- $1,151,000).
7. United States Accounting Principles:
(a) Full cost accounting
US full cost accounting rules differ materially from the Canadian full
cost accounting guidelines followed by Chieftain. The US rules require
an impairment test to be conducted quarterly whereas the Canadian
guidelines require this test only at year-end. In determining the
limitation on carrying values, US rules require the discounting of
future net revenues at 10%; Canadian guidelines require the use of
undiscounted future net revenues and the deduction of estimated future
administrative and financing costs. The quarterly test required by US
accounting rules, using a March 31, 1999 UK natural gas price of $0.84
per Mcf to determine future net revenues, would have resulted in a
write-down of UK property carrying costs at March 31, 1999 of $7.1
million and, after providing for tax recoveries of $3.1 million, a net
charge to operations of $4.0 million.
<PAGE> 8
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(b) Effect on earnings
The effect on consolidated earnings of these differences is summarized
as follows:
<TABLE>
<CAPTION>
Six months Three months
-------------------------- ---------------------------
Period ended June 30, 2000 1999 2000 1999
--------------------------------------------------------------------------------------------------------------------
(US$ in thousands except number of shares and per share amounts)
<S> <C> <C> <C> <C>
Net income (loss) applicable to common shares,
as reported $ 6,017 $ (12,367) $ 3,912 $ (8,507)
Additional depletion difference -- (7,104) -- --
----------- ----------- ----------- -----------
6,017 (19,471) 3,912 (8,507)
Reduction in depletion expense 5,253 8,196 2,605 4,499
Decrease (increase) in deferred tax provision (1,573) 174 (611) (1,657)
----------- ----------- ----------- -----------
Net income (loss) applicable to common shares under
US accounting principles $ 9,697 $ (11,101) $ 5,906 $ (5,665)
=========== =========== =========== ===========
Net income (loss) per common share under US
accounting principles:
- Basic $ 0.60 $ (0.83) $ 0.37 $ (0.42)
=========== =========== =========== ===========
- Fully diluted $ 0.59 $ (0.83) $ 0.36 $ (0.42)
=========== =========== =========== ===========
Fully diluted number of common shares outstanding 16,368,624 13,351,267 16,367,199 13,348,391
=========== =========== =========== ===========
</TABLE>
(c) Effect on balance sheet
The effect on the Consolidated Condensed Balance Sheet of the
differences between Canadian and US accounting principles is as
follows:
<TABLE>
<CAPTION>
AS AT JUNE 30, 2000 December 31, 1999
-------------------------------------------------------------------------------------------------------------
(US$ in thousands) Under US Under US
Accounting Accounting
As reported Principles As reported Principles
----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
Net capital assets $301,865 $219,470 $277,149 $189,501
Deferred tax - asset $ 13,743 $ 22,815 $ 14,636 $ 30,238
Deferred tax - liability $ 20,650 $ -- $ 15,693 $ --
Deficit $(23,387) $(76,060) $(29,404) $(85,757)
</TABLE>
For US reporting purposes, the preferred shares shown as shareholders'
equity in these consolidated condensed financial statements would be
shown outside the equity section.
(d) Stock-based compensation
The Company accounts for its stock-based compensation plan under APB
Opinion 25 and related interpretations, under which no compensation
costs have been recognized in the financial statements for share
option transactions. If compensation costs had been recorded in
accordance with FAS 123, the Company's net income (loss) applicable to
common shares and net income (loss) per common share would approximate
the following pro forma amounts:
<TABLE>
<CAPTION>
Six months Three months
------------------ -------------------
Period ended June 30, 2000 1999 2000 1999
------------------------------------------------------------------------------------------------------
(US$ in thousands except per share amounts)
<S> <C> <C> <C> <C>
Compensation costs, net of tax $ 627 $ 591 $ 277 $ 330
Net income (loss) applicable to common shares
- as reported $9,697 $(11,101) $5,906 $(5,665)
- pro forma $9,070 $(11,692) $5,629 $(5,995)
Net income (loss) per common share
\ Basic
- as reported $ 0.60 $ (0.83) $ 0.37 $ (0.42)
- pro forma $ 0.56 $ (0.88) $ 0.35 $ (0.45)
Fully diluted
- as reported $ 0.59 $ (0.83) $ 0.36 $ (0.42)
- pro forma $ 0.56 $ (0.88) $ 0.35 $ (0.45)
</TABLE>
<PAGE> 9
Page 9 of 19
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
You should read the following discussion and analysis in conjunction with our
accompanying unaudited consolidated condensed financial statements. The
information contains forward looking statements that are subject to risk factors
associated with the oil and gas business. Forward looking statements typically
contain words such as "anticipate", "believe", "expect", "plan" or similar words
suggesting future outcomes. We believe that the expectations reflected in these
statements are reasonable, but may be affected by a variety of factors
including, but not limited to: price fluctuations, currency fluctuations,
drilling and production results, imprecision of reserve estimates, loss of
market, industry competition, environmental risks and capital restrictions.
Our financial statements and information are reported in US dollars and are
prepared based upon Canadian generally accepted accounting principles.
Substantially all of our revenues and a significant portion of our operating
expenses are realized or incurred in US dollars. For a discussion of the effect
of differences in generally accepted accounting principles in Canada and the US
on our financial statements, see Note 12 to our 1999 consolidated financial
statements and Note 7 to our accompanying unaudited consolidated condensed
financial statements.
OVERVIEW
The second quarter of 2000 marked a return to positive growth in our production
volumes, demonstrated by our June 2000 average daily production of 106.5 MMcfe
per day (87.8 MMcfe per day after royalties) compared to the quarter's average
daily production of 94.3 MMcfe per day (78.1 MMcfe per day after royalties).
Strong natural gas prices, and the resurgence in oil prices, contributed to the
achievement of our record first half revenues of $45.7 million, net income
applicable to common shares of $6.0 million and cash flow from operations of
$32.6 million.
FIRST SIX MONTHS 2000 COMPARED TO FIRST SIX MONTHS 1999
PRODUCTION
On an energy equivalent basis our average daily production for the first six
months of 2000 decreased 13% to 96.9 MMcfe per day (80.2 MMcfe per day after
royalties) from 111.3 MMcfe per day (91.7 MMcfe per day after royalties) for the
corresponding period in 1999. Natural gas comprised 74% (before and after
royalties) of our production for the first six months of 2000 and 76% (75% after
royalties) of our production for the corresponding period in 1999. For the first
six months of 2000, our natural gas production decreased 14% to 13.1 Bcf (10.8
Bcf after royalties) compared to 15.3 Bcf (12.5 Bcf after royalties) for the
corresponding period in 1999. Oil and natural gas liquids production for the
same period decreased 6% to 758 MBbls (639 MBbls after royalties) compared to
806 MBbls (686 MBbls after royalties) for the corresponding period in 1999.
A number of factors affected our production volumes during the first half of
2000:
- inherent steeper rates of decline of US Gulf of Mexico wells compared to
onshore wells;
- delays and other difficulties encountered by contractors in constructing new
production facilities; and
- mechanical difficulties encountered while drilling wells that were critical
to achieving development/production timelines.
--------------------------------------------------------------------------------
Unless the context indicates another meaning, the terms "Chieftain", "the
Company", "we", "us" and "our" refer to Chieftain International, Inc., a company
organized under the laws of the Province of Alberta, Canada, and its
subsidiaries.
As used in this Form 10-Q, "Bcf" means 1,000,000,000 cubic feet of natural gas,
"Bcfe" means 1,000,000,000 cubic feet of natural gas equivalent, "boe" means
barrel of oil equivalent using a ratio of 6,000 cubic feet of natural gas = 1
barrel, "MBbls" means 1,000 barrels of crude oil, condensate and natural gas
liquids, "Mcf" means 1,000 cubic feet of natural gas, "Mcfe" means 1,000 cubic
feet of natural gas equivalent using a ratio of 1 barrel = 6,000 cubic feet of
natural gas, "MMcf" means 1,000,000 cubic feet and "MMcfe" means 1,000,000 cubic
feet of natural gas equivalent.
<PAGE> 10
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Eighty-nine percent of our natural gas production for the first six months of
2000 came from our interests in the US Gulf of Mexico region compared to 88% in
the corresponding period in 1999. Our interests in this region accounted for 54%
of our oil and ngls production compared to 49% in the 1999 period. Substantially
all of the remainder of our oil and ngls production arises from our interests in
the Aneth and Ratherford Units in southeast Utah.
During the second quarter of 2000, production commenced onshore Louisiana at
Chacahoula and offshore at South Timbalier 196 and Vermilion 267. These three
properties, which commenced production June 2nd, June 27th and May 22nd,
respectively, collectively were producing, net to our interest, 21.9 MMcf per
day (18.1 MMcf per day after royalties) of natural gas and 828 barrels per day
(679 barrels per day after royalties) of ngls on June 30th.
During the month of June, 2000, we produced 80.6 MMcf per day of natural gas
(66.0 MMcf per day after royalties), of which 77.0 MMcf per day (62.4 MMcf per
day after royalties) was from the US and 3.6 MMcf per day (before and after
royalties) was from the UK. In June, 2000, oil production was 4,310 barrels per
day (3,641 barrels per day after royalties) of which 1,861 barrels per day
(1,625 barrels per day after royalties) was from the Aneth and Ratherford Units
in Utah and 2,432 barrels per day (2,000 barrels per day after royalties) was
from the US Gulf of Mexico region.
<TABLE>
<CAPTION>
Before royalties After royalties
PRODUCTION SUMMARY ------------------ ---------------
Six months ended June 30, 2000 1999 2000 1999
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Natural gas (MMcf per day)
US 64.7 75.3 52.0 59.6
UK 7.2 9.3 7.2 9.3
----- ----- ----- -----
Total 71.9 84.6 59.2 68.9
===== ===== ===== =====
Oil and ngls (barrels per day) 4,167 4,455 3,513 3,792
===== ===== ===== =====
Total natural gas equivalent (MMcfe per day) 96.9 111.3 80.2 91.7
===== ===== ===== =====
Total period equivalent (Bcfe) 17.6 20.1 14.6 16.6
===== ===== ===== =====
</TABLE>
NATURAL GAS AND OIL MARKETING
NATURAL GAS. Natural gas prices averaged $2.70 per Mcf for the first six months
of 2000 compared to $1.70 per Mcf for the corresponding period in 1999. For the
first six months of 2000, we received average natural gas prices of $2.84 per
Mcf in the US and $1.45 per Mcf in the UK compared to $1.79 and $1.00,
respectively, for the corresponding period in 1999. We believe that this
strengthening of prices, in both markets, reflects increasingly tight
supply-demand equations. The Energy Information Administration ("EIA") of the
U.S. Department of Energy has reported that US end-use consumption, through the
first five months of 2000, was similar to that of the comparative 1999 period.
Although end-use consumption was stable, net storage withdrawals increased by 33
percent and imports increased by 4 percent indicating tightness in US natural
gas supply. The EIA, in its July outlook, forecasted US natural gas demand to
increase 4.3% this year from 1999 levels.
OIL AND NGLS. Oil and natural gas liquids prices averaged $25.18 per barrel for
the first six months of 2000 compared to $13.43 per barrel in the 1999 period.
Oil prices in the 2000 first half benefited from the Organization of Petroleum
Exporting Countries' ("OPEC") adherence to production quotas.
At June 30, 2000, we had entered into natural gas forward contracts for the
physical delivery of natural gas volumes totaling 3.3 Bcf (18.1 MMcf per day) at
an average price, net of transportation, of $2.91 per Mcf for the second half of
2000 and 0.9 Bcf (9.4 MMcf per day) at an average price of $4.22 per Mcf for the
first quarter of 2001.
REVENUE
For the first six months of 2000, an 87% increase in oil prices was complemented
by a 59% increase in natural gas prices. The increase in prices more than offset
the production decline with the result that production revenues for the first
six months of 2000 increased 48% ($17.6 million) to $54.4 million ($44.9 million
after royalties) from the corresponding period in 1999.
<PAGE> 11
Page 11 of 19
<TABLE>
<CAPTION>
NET REVENUE
Six months ended June 30, 2000 1999
----------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Natural gas, after royalties
$28,841 $20,962
Oil and ngls, after royalties
16,055 9,423
------- -------
Production revenue, after royalties
44,896 30,385
Interest and other revenue
764 376
------- -------
Total net revenue
$45,660 $30,761
======= =======
</TABLE>
<TABLE>
<CAPTION>
Natural gas
PRICE/VOLUME VARIANCES ----------------------------
Six months ended June 30, US UK Total Oil and ngls Total
---------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
1999 production revenue, after
royalties $19,275 $1,687 $20,962 $ 9,423 $30,385
Price variance 10,055 586 10,641 7,263 17,904
Volume variance (2,388) (374) (2,762) (631) (3,393)
------- ------ ------- ------- -------
2000 production revenue, after
royalties $26,942 $1,899 $28,841 $16,055 $44,896
======= ====== ======= ======= =======
</TABLE>
EXPENSES
ROYALTIES. Our composite royalty rate was unchanged on a period over period
basis.
Our US Gulf of Mexico properties in federal waters generally carry a fixed
one-sixth (16 2/3%) royalty rate. Some of these offshore properties carry
overriding royalties ranging from 1.1% to 10%. UK production carries no royalty
obligations.
We pay no overriding royalties to management or staff.
<TABLE>
<CAPTION>
ROYALTIES
Six months ended June 30, 2000 1999
------------------------------------------------------------------------------
(in thousands except per unit amounts and percentages)
<S> <C> <C>
Natural gas $6,476 $4,822
Oil and ngls 3,043 1,638
------ ------
Total $9,519 $6,460
====== ======
Royalties per Mcfe $ 0.54 $ 0.32
Composite royalty rate 17.5% 17.5%
</TABLE>
PRODUCTION COSTS. Our production costs for the first six months of 2000
decreased 5% compared to the corresponding period in 1999. The increase in per
unit production costs is the composite result of a decrease in the volume of
equivalent production and an increase in production taxes, primarily on Utah oil
production, the amount of such taxes being dependent upon the price of natural
gas and oil.
<TABLE>
<CAPTION>
PRODUCTION COSTS
Six months ended June 30, 2000 1999
--------------------------------------------------------------------------------
(in thousands except per unit amounts)
<S> <C> <C>
Lifting costs $6,066 $6,616
Production taxes 913 746
------ ------
Production costs $6,979 $7,362
====== ======
Production costs ($ per Mcfe)
Before royalty volumes $ 0.40 $ 0.37
After royalty volumes $ 0.48 $ 0.44
</TABLE>
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses
for the first six months of 2000 increased 35% from the corresponding period in
1999. This increase is primarily the result of performance-based compensation
payments which were higher during the first quarter of 2000 than during the
corresponding 1999 period.
<PAGE> 12
Page 12 of 19
<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE
Six months ended June 30, 2000 1999
------------------------------------------------------------------------------
(in thousands except per unit amounts and percentages)
<S> <C> <C>
Gross general and administrative expenses $6,047 $4,563
Capitalized expenses (2,853) (2,190)
------ ------
General and administrative expenses $3,194 $2,373
====== ======
General and administrative expenses ($ per Mcfe)
Before royalty volumes $ 0.18 $ 0.12
After royalty volumes $ 0.22 $ 0.14
Capitalization ratio 47% 48%
</TABLE>
INTEREST EXPENSE. Our interest expense for the first six months of 2000
decreased compared to the corresponding 1999 period due to reduced credit
facility utilization. Our weighted average debt outstanding for the six months
ended June 30, 2000 was $11.3 million compared to $42.5 million for the
corresponding period in 1999. The effective interest rate on our outstanding
debt for the six months ended June 30, 2000 was 7.12% compared to 5.67% for the
corresponding period in 1999. The weighted average interest rate on our debt at
June 30, 2000 was 7.40%.
DEPLETION AND AMORTIZATION. Our depletion and amortization expense for the
first six months of 2000 decreased 17% from the corresponding period in 1999 as
a result of a 13% decrease in our production and a 5% decrease in our average
depletion rate to $1.18 per Mcfe ($1.42 per Mcfe after royalties). Our depletion
rate decreased for a number of reasons:
- our 1999 finding and development cost for proved reserves was $0.68 per Mcfe
($0.84 per Mcfe after royalties);
- the recovery in oil prices which resulted in upward revisions in our proved
reserves at December 31, 1999 compared to December 31, 1998; and
- the ceiling test write-down of the UK properties that occurred at December
31, 1999 due to low spot market prices for natural gas as at that date.
In Libya, we and our partners concluded that the multi-year exploration program,
and the production test which commenced in December 1997, were not commercial
under the terms of the concession and therefore terminated the venture. As a
result, additional depletion of $11.4 million was recorded in the second quarter
of 1999 to eliminate the investment.
NET INCOME (LOSS) APPLICABLE TO COMMON SHARES
After provision of $2.5 million for dividends on preferred shares of a
subsidiary in both periods, net income (loss) applicable to common shares for
the first six months of 2000 was $6.0 million, an improvement of $18.4 million
compared to the year earlier period. The two most significant factors
responsible for the improvement were the improvement in natural gas and oil
prices in the current year and the non-recurring nature of the write-off of the
Libyan investment, which occurred in 1999.
<TABLE>
<CAPTION>
Before royalties After royalties
NETBACK ANALYSIS ($ per Mcfe) ---------------- ----------------
Six months ended June 30, 2000 1999 2000 1999
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Gross production revenue $ 3.08 $ 1.83
Royalties (0.54) (0.32)
------ ------
Production revenue, after royalties 2.54 1.51 $ 3.07 $ 1.83
Production costs (0.40) (0.37) (0.48) (0.44)
------ ------ ------ ------
Gross margin 2.14 1.14 2.59 1.39
General and administrative expenses (0.18) (0.12) (0.22) (0.14)
------ ------ ------ ------
Gross profit 1.96 1.02 2.37 1.25
Interest and other 0.03 (0.04) 0.03 (0.05)
Preferred share dividends (0.14) (0.12) (0.17) (0.15)
------ ------ ------ ------
Cash flow from operations $ 1.85 $ 0.86 $ 2.23 $ 1.05
====== ====== ====== ======
Total production volume (Bcfe) 17.6 20.1 14.6 16.6
====== ====== ====== ======
</TABLE>
<PAGE> 13
Page 13 of 19
THREE MONTHS ENDED JUNE 30, 2000 COMPARED TO THREE MONTHS ENDED JUNE 30, 1999
PRODUCTION
On an energy equivalent basis our average daily production decreased 17% to 94.3
MMcfe per day (78.1 MMcfe per day after royalties) for the second quarter of
2000 from 113.4 MMcfe per day (93.3 MMcfe per day after royalties) for the
corresponding period in 1999. Natural gas comprised 73% (before and after
royalties) of our production for the second quarter of 2000 and 72% (before and
after royalties) of our production for the corresponding period in 1999. For the
second quarter of 2000, our natural gas production decreased 16% to 6.3 Bcf (5.2
Bcf after royalties) compared to 7.5 Bcf (6.1 Bcf after royalties) for the
corresponding period in 1999. Oil and natural gas liquids production for the
quarter decreased 20% to 380 MBbls (321 MBbls after royalties) compared to 475
MBbls (402 MBbls after royalties) for the 1999 second quarter.
Ninety-one percent of our natural gas production for the second quarter of 2000
came from our interests in the US Gulf of Mexico region compared to 90% in the
corresponding period in 1999. Our interests in this region accounted for 59% of
our oil and ngls production compared to 58% in the corresponding 1999 period.
Substantially all of the remainder of our oil and ngls production arises from
our interests in the Aneth and Ratherford Units in southeast Utah.
<TABLE>
<CAPTION>
Before royalties After royalties
PRODUCTION SUMMARY ---------------- ---------------
Three months ended June 30, 2000 1999 2000 1999
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Natural gas (MMcf per day)
US 63.4 74.4 51.0 59.1
UK 5.9 7.7 5.9 7.7
----- ----- ----- -----
Total 69.3 82.1 56.9 66.8
===== ===== ===== =====
Oil and ngls (barrels per day) 4,181 5,222 3,531 4,421
===== ===== ===== =====
Total natural gas equivalent (MMcfe per day) 94.3 113.4 78.1 93.3
===== ===== ===== =====
Total period equivalent (Bcfe) 8.6 10.3 7.1 8.5
===== ===== ===== =====
</TABLE>
NATURAL GAS AND OIL MARKETING
NATURAL GAS. Natural gas prices averaged $3.04 per Mcf for the second quarter
of 2000 compared to $1.86 per Mcf for the corresponding period in 1999. For the
second quarter of 2000, we received average natural gas prices of $3.18 per Mcf
in the US and $1.58 per Mcf in the UK compared to $1.97 and $0.82, respectively,
for the corresponding period in 1999.
OIL AND NGLS. Oil and natural gas liquids prices averaged $26.30 per barrel for
the second quarter of 2000 compared to $15.17 per barrel for the corresponding
period in 1999. Oil prices in the 2000 second quarter benefited from OPEC's
adherence to production quotas.
REVENUE
For the second quarter of 2000, a 73% increase in oil prices was complemented by
a 63% increase in natural gas prices. The increase in prices more than offset
the production decline with the result that production revenues for the second
quarter of 2000 increased 38% ($8.1 million) to $29.2 million ($24.1 million
after royalties) from the corresponding period in 1999.
<TABLE>
<CAPTION>
NET REVENUE
Three months ended June 30, 2000 1999
--------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Natural gas, after royalties $15,722 $11,161
Oil and ngls, after royalties 8,400 6,190
------- -------
Production revenue, after royalties 24,122 17,351
Interest and other revenue 314 192
------- -------
Total net revenue $24,436 $17,543
======= =======
</TABLE>
<PAGE> 14
Page 14 of 19
<TABLE>
<CAPTION>
Natural gas
PRICE/VOLUME VARIANCES ---------------------------
Three months ended June 30, US UK Total Oil and ngls Total
-------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
1999 production revenue, after
royalties $10,592 $ 569 $11,161 $ 6,190 $17,351
Price variance 5,704 415 6,119 3,213 9,332
Volume variance (1,426) (132) (1,558) (1,003) (2,561)
------- ----- ------- ------- -------
2000 production revenue, after
royalties $14,870 $ 852 $15,722 $ 8,400 $24,122
======= ===== ======= ======= =======
</TABLE>
EXPENSES
ROYALTIES. Our composite royalty rate is comparable on a period over period
basis.
<TABLE>
<CAPTION>
ROYALTIES
Three months ended June 30, 2000 1999
------------------------------------------------------------------------------
(in thousands except per unit amounts and percentages)
<S> <C> <C>
Natural gas $3,424 $2,650
Oil and ngls 1,642 1,120
------ ------
Total $5,066 $3,770
====== ======
Royalties per Mcfe $ 0.59 $ 0.37
Composite royalty rate 17.4% 17.8%
</TABLE>
PRODUCTION COSTS. Our production costs for the second quarter of 2000 decreased
11% compared to the corresponding period in 1999. The increase in per unit
production costs is the composite result of a decrease in the volume of
equivalent production and an increase in production taxes, primarily on Utah oil
production, the amount of such taxes being dependent upon the price of natural
gas and oil.
<TABLE>
<CAPTION>
PRODUCTION COSTS
Three months ended June 30, 2000 1999
------------------------------------------------------------------------------
(in thousands except per unit amounts)
<S> <C> <C>
Lifting costs $3,149 $3,670
Production taxes 470 380
------ ------
Production costs $3,619 $4,050
====== ======
Production costs ($ per Mcfe)
Before royalty volumes $ 0.42 $ 0.39
After royalty volumes $ 0.51 $ 0.48
</TABLE>
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses
for the second quarter of 2000 increased 34% from the corresponding period in
1999. This increase is a composite of a number of items, the most significant
being increased staffing levels and, to a lesser degree, increased legal fees,
office rent and corporate communication costs.
<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE
Three months ended June 30, 2000 1999
-------------------------------------------------------------------------------
(in thousands except per unit amounts and percentages)
<S> <C> <C>
Gross general and administrative expenses $ 2,494 $1,998
Capitalized expenses (1,093) (954)
------- ------
General and administrative expenses $ 1,401 $1,044
======= ======
General and administrative expenses ($ per Mcfe)
Before royalty volumes $ 0.16 $ 0.10
After royalty volumes $ 0.20 $ 0.12
Capitalization ratio 44% 48%
</TABLE>
INTEREST EXPENSE. Our interest expense for the second quarter of 2000 decreased
compared to the corresponding 1999 period due to reduced credit facility
utilization. Our weighted average debt outstanding for the three months ended
June 30, 2000 was $12.5 million compared to $44.9 million for the corresponding
period in 1999. The effective interest rate on our outstanding debt for the
quarter ended June 30, 2000 was 7.22% compared to 5.61% for the corresponding
period in 1999.
DEPLETION AND AMORTIZATION. Our depletion and amortization expense for the
second quarter of 2000 decreased 21% from the corresponding period in 1999 as a
result of a 17% decrease in our production and a 4% decrease in our average
depletion rate to $1.19 per Mcfe ($1.44 per Mcfe after royalties).
<PAGE> 15
Page 15 of 19
NET INCOME (LOSS) APPLICABLE TO COMMON SHARES
After provision of $1.2 million for dividends on preferred shares of a
subsidiary in both periods, net income (loss) applicable to common shares for
the second quarter of 2000 was $3.9 million, an improvement of $12.4 million
compared to the year earlier period. The two most significant factors
responsible for the improvement were the improvement in natural gas and oil
prices in the current year and the non-recurring nature of the write-off of the
Libyan investment, which occurred in 1999.
<TABLE>
<CAPTION>
Before royalties After royalties
NETBACK ANALYSIS ($ per Mcfe) ---------------- ----------------
Three months ended June 30, 2000 1999 2000 1999
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Gross production revenue $ 3.40 $ 2.05
Royalties (0.59) (0.37)
------ ------
Production revenue, after royalties 2.81 1.68 $ 3.39 $ 2.04
Production costs (0.42) (0.39) (0.51) (0.48)
------ ------ ------ ------
Gross margin 2.39 1.29 2.88 1.56
General and administrative expenses (0.16) (0.10) (0.20) (0.12)
------ ------ ------ ------
Gross profit 2.23 1.19 2.68 1.44
Interest and other 0.00 (0.05) 0.02 (0.04)
Preferred share dividends (0.14) (0.12) (0.17) (0.15)
------ ------ ------ ------
Cash flow from operations $ 2.09 $ 1.02 $ 2.53 $ 1.25
====== ====== ====== ======
Total production volume (Bcfe) 8.6 10.3 7.1 8.5
====== ====== ====== ======
</TABLE>
CAPITAL EXPENDITURES
Our capital expenditures during the first six months of 2000 totaled $44.9
million compared to $19.7 million for the corresponding period in 1999.
LEASE AND LAND HOLDINGS. During the first six months of 2000, we participated
in high bids for 11 offshore blocks, 5 as operator, covering 55,700 (28,500 net)
acres at the Federal US Central Gulf of Mexico Lease Sale held on March 15,
2000. Our share of the bids on the 11 blocks, all of which have been awarded,
was $3.7 million.
DRILLING RESULTS. For the first six months of 2000, our exploratory drilling
success rate in the US Gulf of Mexico region was 45% compared to 80% for the
corresponding period in 1999. Including development wells, our success rate in
the region was 54% for the first six months of 2000 compared to 83% for the
corresponding period in 1999. Drilling in all areas resulted in success rates of
54% for the first six months of 2000 and 63% for the first six months of 1999.
<TABLE>
<CAPTION>
2000 1999
DRILLING RESULTS (WELLS) ------------- -------------
Six months ended June 30, GROSS NET Gross Net
--------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
US - Gulf of Mexico region
Successful 7 2.72 5 2.04
Dry 6 2.23 1 0.20
-- ---- -- ----
13 4.95 6 2.24
-- ---- -- ----
Foreign
Dry -- -- 2 0.25
-- ---- -- ----
Total wells drilled
Successful 7 2.72 5 2.04
Dry 6 2.23 3 0.45
-- ---- -- ----
13 4.95 8 2.49
== ==== == ====
Chieftain operated wells 4 2.00 1 0.50
== ==== == ====
</TABLE>
In addition to the wells described above, at June 30, 2000 we had interests in 4
(1.41 net) wells which were drilling compared to 1 (0.50 net) at June 30, 1999.
One additional well was successfully drilled in the six months ended June 30,
2000 on our US Gulf of Mexico acreage at no cost to us. For the six months ended
June 30, 1999, two unsuccessful wells were drilled on our US Gulf of Mexico
acreage at no cost to us.
<PAGE> 16
Page 16 of 19
CAPITAL FIELD DEVELOPMENT ACTIVITY. Our principal development activities during
the first half of 2000 were at South Timbalier 196, Vermilion 267 and West
Cameron 613 where platform jackets and topsides (containing production
facilities) were loaded out and installed and accompanying pipelines were laid
at South Timbalier 196 and Vermilion 267. At quarter end, construction was in
progress, and expenditures were being recorded, for facilities at the onshore
Langlinais #1 well in the Northeast Wright Field, as well as for jackets and
topsides at High Island A-530, Matagorda Island 704 and West Cameron 300.
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES SUMMARY
Six months ended June 30, 2000 1999
--------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Property acquisition costs:
US $ 5,801 $ 1,769
UK 24 29
------- -------
5,825 1,798
------- -------
Sale of producing properties:
US -- (155)
------- -------
Exploration costs:
US 18,995 8,602
UK (5) (7)
Foreign -- 1,531
------- -------
18,990 10,126
------- -------
Development costs:
US 20,103 7,940
UK 2 (7)
------- -------
20,105 7,933
------- -------
$44,920 $19,702
======= =======
</TABLE>
CAPITAL RESOURCES AND LIQUIDITY
Our primary sources of cash are funds generated from operations and from
financing activities. Our primary cash outflows are for exploration and
development activities.
Cash flow from operations, a frequently used measure of performance for
exploration and production companies, is derived by adjusting net income (loss)
attributable to common shares to eliminate the effects of depletion and
amortization and deferred income taxes. We generated cash flow from operations
of $32.6 million during the first six months of 2000 compared to $17.3 million
for the corresponding period in 1999. The variance is primarily a function of
increased commodity prices in the first half of 2000.
In 1997, a third-party sold its interests in producing properties that we
currently operate and since that time neither the vendor nor the purchaser has
reimbursed us on a timely basis for expenditures made by us, as operator, for
their account. Accordingly, we have commenced an action in the Louisiana courts
against both the vendor and the purchaser to recover the amounts currently owing
to us, approximately $3.6 million, plus interest and costs. Although the
purchaser filed for Chapter 11 bankruptcy in the first half of 2000, we
currently expect to recover all current and future amounts outstanding and have
therefore made no allowance for doubtful collectability.
Financing activities during the six months ended June 30, 2000 provided $5
million of cash, the net result of:
- the drawdown of $5 million of our revolving bank credit facility, which
adjusts the unutilized portion to $85 million.
Financing activities during the corresponding period in 1999 provided $4.9
million of cash, the net result of:
- the drawdown of $5 million of our revolving bank credit facility; and
- the purchase for cancellation of 7,500 common shares at the cost $0.1 million
under our share repurchase program, which expired on November 1, 1999.
Cash used in investing activities increased 128% to $44.9 million for the first
six months of 2000 from $19.7 million for the corresponding period in 1999.
<PAGE> 17
Page 17 of 19
<TABLE>
<CAPTION>
COMPOSITION OF NATURAL RESOURCE INVESTING ACTIVITIES
Six months ended June 30, 2000 1999
--------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Leasehold and seismic $ 6,873 $ 3,745
Sale of producing properties -- (155)
Exploratory drilling 17,942 8,179
Development drilling 9,056 3,805
Capital field development 11,049 4,128
------- -------
Total $44,920 $19,702
======= =======
</TABLE>
Our June 30, 2000 cash balance of $4.8 million was up $1.7 million from the
balance at June 30, 1999. We had outstanding borrowings of $15 million on our
$100 million revolving bank credit facility at June 30, 2000. The weighted
average interest rate for our borrowings during the first six months was 7.12%.
OUTLOOK
Five projects are expected to commence production during the latter half of
2000: the onshore Langlinais #1 well in the Northeast Wright Field, High Island
A-530, Matagorda Island 704, West Cameron 300 and West Cameron 613. At High
Island A-510/A-531, it was deemed prudent to drill an additional well, which was
successfully drilled late in the second quarter of 2000, to identify the best
processing scenario as a result of which planned initial production has been
rescheduled to the first quarter of 2001. Due in part to a delay arising from
the change in ownership of a platform through which we contemplated processing
our Eugene Island 189 production, anticipated initial production has been
rescheduled to the first half of 2001.
Our 2000 annual production is likely to be only slightly higher than the rates
realized in 1999. Our June 2000 US production exit rate was 102.8 MMcfe per day
(84.2 MMcfe per day after royalties). This rate is 3% higher than our December
1999 US production exit rate of 99.5 MMcfe per day (81.1 MMcfe per day after
royalties). With five new fields commencing production in the second half of
2000, our December 2000 production exit rate should be significantly higher than
the year prior rate and should give us a strong start to 2001.
Based on current prices and anticipated production volumes, our revenues, net
income and cash flow from operations for the second half of 2000 are expected to
be significantly improved over first half results.
We continue to expect that our 2000 capital expenditure program will be
approximately $86 million and will include the drilling of approximately 27
wells in the US Gulf of Mexico region. We expect to fund these expenditures from
operating cash flow and our unsecured revolving bank credit facility. Capital
expenditures can vary significantly as a result of exploration success,
availability of equipment and services and opportunities. During the quarter
ended June 30, 2000, demand for, and utilization of, drilling rigs in the US
Gulf of Mexico has increased, putting upward pressure on day rates. As an active
explorer of internally generated natural gas and oil prospects, we are in a
strong position to compete in the current environment. We will continue to focus
on natural gas exploration and development in the US Gulf of Mexico region.
<PAGE> 18
Page 18 of 19
PART II
ITEM 1. LEGAL PROCEEDINGS
We are, in the ordinary course of business, party to various legal
proceedings. In the opinion of our management, none of these
proceedings, either individually or in the aggregate, is material.
ITEM 2. CHANGES IN SECURITIES
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
There have been no defaults upon senior securities of Chieftain.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
a. An annual meeting of shareholders of the company was held on May 25,
2000.
b. Directors elected for a term of three years were: S. C. Hurley, J.
E. Maybin, and E. S. Ondrack. Other directors whose terms of office
as directors continued after the meeting are: S. A. Milner, D. E.
Mitchell, H. J. Kelly, L. G. Munin and S. T. Peeler
c. The matters voted upon and the results of the voting were as
follows:
(i) The shareholders voted 12,797,830 shares in the affirmative
and withheld from voting 54,350 shares to elect S. C. Hurley,
J. E. Maybin, and E. S. Ondrack as directors to hold office
for a term of three years.
(ii) The shareholders voted 12,810,670 shares in the affirmative
and withheld from voting 41,510 shares to appoint
PricewaterhouseCoopers LLP as auditors of the Company to hold
office until the close of the next annual meeting.
(iii) The shareholders voted 9,167,323 shares for and 2,824,670
shares against the amendment of the Share Option Plan.
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS OF FORM 8-K
None
<PAGE> 19
Page 19 of 19
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Chieftain International, Inc.
-----------------------------
(Registrant)
/s/STANLEY A. MILNER
-----------------------------------------
Stanley A. Milner, A.O.E., LL.D.
President and Chief Executive Officer
Principal Executive and Financial Officer
Dated: July 17, 2000
